Underwater scrubbing of CO2 from CO2-containing hydrocarbon resources

ABSTRACT

A method for removing CO 2  from a CO 2 -containing hydrocarbon asset. The process includes contacting a CO 2 -containing hydrocarbon asset with an aqueous liquid stream at an underwater location so that at least a portion of the CO 2  in the hydrocarbon asset is dissolved into the aqueous liquid stream, creating a CO 2 -depleted hydrocarbon asset and a CO 2 -enriched aqueous stream. The CO 2 -enriched aqueous stream is separated from the hydrocarbon asset. Finally, the CO 2 -enriched aqueous stream is disposed of in at least one of a marine environment, a terrestrial formation, or combination thereof.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The present invention is directed to producing CO₂-depleted hydrocarbonsfrom CO₂-rich hydrocarbon resources. In particular, the presentinvention is directed to underwater scrubbing of CO₂-containinghydrocarbon resources with an aqueous stream to produce a CO₂-depletedhydrocarbon resource and a CO₂-enriched aqueous stream.

2. Description of the Related Art

CO₂ is a well known environmental pollutant that contributes toatmospheric warming via the Greenhouse effect. CO₂ is a commoncontaminant in hydrocarbon resources such as, for example, natural gas.Generally, only a minimal amount, typically less than about 10 mole %,preferably less than about 5 mole %, of CO₂ can be tolerated in anatural gas feed to a synthesis gas generating process. Unfortunately,in instances where CO₂-rich hydrocarbon resources have CO₂ levels higherthan about 10 mole %, no economic method exists for removing the CO₂from the hydrocarbon resources. In addition, when the CO₂ is removed,disposal of the CO₂ is problematic.

Efforts have been made to dispose of CO₂ by injecting it as a compressedgas into underground reservoirs. Also, studies have been done todetermine whether CO₂ can be disposed of in deep marine environments.However, in existing CO₂ disposal methods, CO₂ is obtained in arelatively pure state by compressing it and/or condensing it. Thus, adisadvantage of such disposal techniques is that they require costlycompressors and/or refrigerators to compress and/or condense CO₂.

For example, U.S. Pat. No. 6,190,301, to Murray, describes a process andvehicle for disposal of CO₂. In Murray, gaseous CO₂ is first solidifiedand allowed to free fall in a marine environment through open waterwhere it at least partially embeds itself into sedimentary formations.Sedimentation of the CO₂ ensures that the marine environment serves as acarbon sink through carbonate sequestration. Accordingly, Murraydescribes converting gaseous CO₂ into a solid, requiring the use ofexpensive refrigeration and compression processes.

Also, U.S. Pat. No. 6,170,264 to Viteri, describes a low or no pollutionengine for delivering power to vehicles or for other power applications.In the engine of Viteri, fuel and oxygen are combusted within a gasgenerator, generating water and CO₂ with carbon-containing fuels. Thecombustion products, steam, carbon-containing fuels and CO₂ are thenpassed through a condenser where the steam is condensed and the CO₂ iscollected or discharged. The CO₂ is compressed and cooled so that it isin a liquid phase or super critical state. The dense phase CO₂ is thenfurther pressurized to a pressure matching a pressure, less hydrostatichead, existing deep within a porous geological formation, a deepaquifer, a deep ocean location or a terrestrial formation from whichreturn of the CO₂ into the atmosphere is inhibited. Accordingly, Viteridescribes disposing of CO₂ from a power generation plant into the oceanor a terrestrial formation, wherein CO₂ gas is first compressed andcooled to form a liquid phase which is then further compressed to matchthe hydrostatic head.

As a result, there is an urgent need for a process and apparatus thatcan economically remove CO₂ from hydrocarbon resources, without havingto employ costly compression and/or condensation processes, and that candispose of the removed CO₂ in a manner that isolates the CO₂ from theenvironment.

SUMMARY OF THE INVENTION

The present invention satisfies the above objectives by providing aprocess that not only economically removes CO₂ from hydrocarbonresources, but also disposes of the removed CO₂ in a manner thatisolates the CO₂ from the environment.

The process of the present invention removes CO₂ from hydrocarbonresources by contacting a hydrocarbon resource with an aqueous stream,preferably at an elevated pressure. More specifically, processes of thepresent invention separate CO₂ from a hydrocarbon resource by scrubbingthe resource with an aqueous stream at elevated pressure, producing aCO₂-containing aqueous stream that can be disposed of, for example, inat least one of a marine environment, a terrestrial formation orcombination thereof. Thus, one important advantage of the presentinvention is that it can remove CO₂ from hydrocarbon resources withouthaving to use costly compression and/or condensation processes. Anadditional advantage, is that the present invention can dispose ofremoved CO₂ in an aqueous stream in, for example, a marine environment,a terrestrial formation or combination thereof, thereby effectivelyisolating the CO₂ from the environment.

In particular, a process, according to the present invention, forremoving CO₂ from a CO₂-containing hydrocarbon asset can includecontacting the hydrocarbon asset with an aqueous stream at an underwaterlocation so that at least a portion of the CO₂ in the hydrocarbon assetis dissolved into the aqueous stream, creating a CO₂-depletedhydrocarbon asset and a CO₂-enriched aqueous stream. The CO₂-enrichedaqueous stream is then separated from the hydrocarbon asset. Finally theCO₂-enriched aqueous stream is disposed of in at least one of a marineenvironment, a terrestrial formation or combination thereof.

In addition, a method, according to the present invention, for producinga CO₂-depleted hydrocarbon gas from a hydrocarbon/CO₂ gas mixture caninclude contacting a hydrocarbon/CO₂ gas mixture underwater with anaqueous stream, so that at least a portion of the CO₂ in the gas mixtureis dissolved into the aqueous stream, creating a CO₂-depletedhydrocarbon gas and a CO₂-enriched aqueous stream. Next, theCO₂-enriched aqueous stream is separated from the gas stream. Finally, aCO₂-depleted hydrocarbon gas is produced.

BRIEF DESCRIPTION OF THE FIGURES OF THE DRAWING

FIG. 1 is a schematic view of a preferred embodiment of a process forproducing CO₂-depleted hydrocarbons, according to the present invention.

FIG. 2 is a schematic view of another preferred embodiment of a processfor producing CO₂-depleted hydrocarbons, according to the presentinvention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the present invention, at least a portion of CO₂ present in aCO₂-containing hydrocarbon is removed by contacting the CO₂-containinghydrocarbon with an aqueous stream, preferably at an elevated pressure.Once the CO₂ has been removed, a CO₂-enriched aqueous stream isgenerated and is disposed of, for example, in at least one of a marineenvironment, a terrestrial formation or combination thereof, so that theCO₂ is sufficiently isolated from the environment.

Thus, in the present invention, CO₂ in a hydrocarbon resource such as,for example, a natural gas, can be removed and then isolated from theenvironment by scrubbing using an aqueous stream, such as sea water, inan underwater location to produce a CO₂-depleted hydrocarbon resourceand a CO₂-enriched aqueous stream. One important advantage of a processof the present invention is that because it is conducted underwater, itcan inexpensively perform scrubbing using sea water as a low costadsorbent. Another advantage of the present invention is that becausethe process is conducted underwater, scrubbing can be inexpensivelyconducted at a pressure greater than about atmospheric pressure, therebyenhancing CO₂ dissolution. An additional advantage of the presentinvention is that because the process is conducted underwater, theprocess can substantially minimize and/or eliminate the need for costlygas compressors and/or liquid pumps to increase the pressure of anadsorbent used to separate CO₂ from a hydrocarbon resource. Yet anotheradvantage of the present invention is that by disposing of theCO₂-enriched aqueous stream in at least one of a marine environment, aterrestrial formation or combination thereof, the present inventiondisposes of removed CO₂ in a manner that isolates the CO₂ from theenvironment.

Scrubbing of CO₂ from gases using aqueous liquids, according to thepresent invention, should be conducted at non-extreme pressures to avoidformation of methane, CO₂ and other hydrates. The dissolution of CO₂ inwater is enhanced at elevated pressures. Thus, it is preferable tooperate at pressures that are as high as possible. However, to minimizecost, it is preferable to operate at an elevated pressure withoutemploying expensive gas compression processes.

In addition to pressure, temperature and salinity can also be importantduring processing. For instance, at relatively high temperatures,hydrate formation can occur. Also, at relatively low temperatures, ahigher solubility of gas into water and a higher selectivity for removalof CO₂ over methane and other valuable hydrocarbons can be achieved.Salinity can also affect the solubility of hydrocarbons in water. Forinstance, a greater “salting-out” effect can occur on non-ionichydrocarbons like methane. Accordingly, in processes of the presentinvention, temperature and salinity of the aqueous stream can be variedto maximize selectivity for CO₂ removal. Further, in instances where seawater is used as the aqueous stream, salt in the sea water can exhibit aslight tendency to reduce the temperature at which hydrates form.

It is known in the art that the maximum pressure that can be toleratedto avoid hydrate formation at various temperatures for methane and CO₂are as follows:

Pure Methane Pure Carbon Dioxide Temperature 2° C. 8° C. 0° C. 10° C.Maximum 2.9 MPa 6.1 MPa 1.3 Mpa 14 Mpa Pressure, Psia (430 psi) (900psi) (192 psi) (2000 psi) Equivalent 1,000 ft 2,100 ft 450 ft 4,800 ftHydrostatic Water Depth, Feed (62.4 lb/ft₃ water density)

The above data can be found, for example, in E. Dendy Sloan, Jr.,“Clathrate Hydrates of Natural Gases,” Marcel Dekker, Inc. 1990, theentire disclosure of which is incorporated herein by reference. Sloanalso provides numerous examples of gas mixtures and resultingtemperatures/pressures at which hydrates form. Suitable operatingtemperature/pressure combinations are determined on a case by case basisfor each gas composition. Sloan describes methods for estimatingsuitable operating conditions. For instance, for a typical light gas,hydrate formation can be avoided by operating at about 300 psig andabout 10° C.

Generally, to avoid hydrate formation, a pressure less than maximum mustbe used. However, hydrate formation can also be controlled via kineticsand/or heat transfer. Thus, pressure near or above a maximum limit canbe used as long as residence time is minimized.

Henry's Law constants for CO₂ and CH₄ in pure water and sea water, asdescribed, for example, in Clifford N. Click, “Applications of Henry'sLaw to Waste and Process Water VOC Emissions,” 85^(th) Annual MeetingAir and Waste Management Association, are as follows:

Methane Carbon Dioxide Temperature 0° C. 30° C. 0° C. 30° C. Henry's Law22,000 42,000 740 1,850 Constant in Water (atm/mole fraction) Henry'sLaw 40,000 740 Constant in Sea Water (estimated)

Click provides Henry's Law coefficients for several light hydrocarbongases in water as a function of temperature and also provides anequation for the brine effect. Gianni Astartita, David Savage, andAttilio Bisio, “Gas Treating with Chemical Solvents,” Wiley, p. 208,discloses a plot of Henry's Law coefficient physical solubility of CO₂into water as a function of temperature. In addition, John Nighswander,Nicholas Kalogerakis, Anil Mehrotra, “Solubilities of Carbon Dioxide inWater and 1 Wt % NaCl Solution at Pressures up to 10 MPa andTemperatures from 80 to 200 Degrees C.,” J. Chem. Eng. Data 1989, 34, p.355-360, discloses that the effect of salt on CO₂ solubility in waterover temperatures ranging from 80 to 200° C. and pressures up to 10 MPais minimal. The disclosures of Sloan, Click, Astartita and Nighswanderare incorporated herein by reference in their entireties.

The above data show that using sea water and/or operating at elevatedtemperatures can enhance the selectivity of CO₂ removal. However, insome circumstances using sea water for scrubbing is impractical becauseof the introduction of sea water contaminants into the gas stream. Thiscan occur, for example, when using sea water to scrub CO₂ from aFischer-Tropsch tail gas stream that is recycled to a Fischer-Tropsch ormethane reformer reactor. Generally, the presence of contaminants shouldnot hinder the use of sea water for scrubbing a fuel gas stream from aFischer-Tropsch process derived from a tail gas.

A preferred embodiment of a process, according to the present invention,for producing CO₂-depleted hydrocarbons from CO₂-containing hydrocarbonsby underwater scrubbing is depicted in FIG. 1. In this embodiment, aCO₂-containing hydrocarbon asset stream 11 is provided from aCO₂-containing hydrocarbon asset source 10. If necessary, the pressureof the CO₂-containing hydrocarbon asset stream 11 is reduced in apressure reducer 12. The CO₂-containing hydrocarbon asset stream 11 thenenters a scrubber 13. A stream of sea water 14 enters the scrubber 13.Scrubbing is conducted, producing a CO₂-depleted hydrocarbon stream 15and a CO₂-containing sea water stream 18. The CO₂-depleted hydrocarbonstream 15 travels above the surface of the water 16 where it is eitherstored or used for applications including, but not limited to, electricpower generation, fuel, syngas generation. The CO₂-containing sea waterstream 18 is disposed of by being injected into at least one of a marineenvironment or a CO₂ disposal reservoir 20 under the sea bed 17 in adisposal stream 19. An important advantage of this embodiment is thatboth the sea water used for scrubbing and the hydrocarbon gas asset areat elevated pressures, facilitating dissolution of CO₂ into the seawater.

Following separation of the CO₂-enriched aqueous stream, theCO₂-depleted hydrocarbon asset can be further processed. For example,after separation of the CO₂-enriched aqueous stream, the resultingCO₂-depleted hydrocarbon asset can be processed using at least onesuitable processing step including, but not limited to, compression,condensation, separation of liquids, sulfur removal, dehydration,mercury removal, radon removal, blending with other gas streams,heating, valve adjustment, combinations thereof and the like. Moreover,after separation of the CO₂-enriched aqueous stream and/or furtherprocessing, the CO₂-depleted hydrocarbon asset can be transported tomarket for use in various applications. For instance, suitableapplications for CO₂-depleted hydrocarbon assets produced by the presentinvention include, but are not limited to, electric power generation,furnace fuel, syngas generation, GTL feed stock, methanol feed stock,combinations thereof and the like.

Although the scrubber, depicted in FIG. 1, is positioned between thesurface of the water and the sea bed, the scrubber can be at anylocation under the water including, but not limited to, immediatelyunder the sea level at the production platform, between the productionplatform and the sea bed, on the sea bed, or even under the sea bed.However, if the hydrocarbon gas asset stream is at a pressure greaterthan the hydrostatic head at the location of the scrubber, the pressureof the hydrocarbon asset can be reduced to the hydrostatic pressure ofthe scrubber. If the hydrocarbon gas asset stream is at a pressuregreater than the hydrostatic head at the sea bed, the scrubber ispreferably positioned on the sea bed and is associated with otherproduction equipment located at this position. Also, if the pressure ofthe hydrocarbon asset stream is less than the hydrostatic pressure atthe sea bed, it is preferable to have the scrubber located at a positionabove the sea bed where the pressure of the asset matches or exceeds thehydrostatic pressure, rather than being positioned on the sea bed. Bypositioning the scrubber above the sea bed, the present invention canavoid having to compress the hydrocarbon asset stream to achieve thehydrostatic pressure. If the pressure of the hydrocarbon asset stream isless than the hydrostatic pressure at the sea bed, the scrubber ispreferably positioned immediately under the sea level at the productionplatform and is associated with other production equipment located inthis position. Further, in preferred embodiments contacting of theaqueous liquid stream and the hydrocarbon asset is performed at a depthwhere hydrostatic water pressure is less than or equal to a pressure ofa source of the hydrocarbon asset.

Preferably, the temperature of the scrubber is left uncontrolled andremains at ambient conditions. However, under certain situations, it maybe preferable to either heat or cool the scrubber to facilitate CO₂removal from the hydrocarbon gas asset stream. For example, if thehydrocarbon gas asset stream includes a viscous liquid, heating may bedesirable. In addition, if larger amounts of CO₂ are intended to beremoved from the hydrocarbon gas asset stream, cooling may be desirable.

The source of the sea water, or alternative aqueous liquid, in processesof the present invention, can either be adjacent to the scrubber or canbe positioned some distance away from the scrubber. For example, if coldsea water is desired, and the cold sea water is available at a differentlocation, the cold sea water may be delivered, for example, though apipe to the scrubber. Preferably, the source of the sea water, oralternative aqueous liquid, is in close proximity to the scrubber. Inpreferred embodiments, the aqueous liquid source is within about 1kilometer of the scrubber and more preferably is within about 100 metersof the scrubber.

In processes of the present invention, it is preferable to avoidscrubbing streams that also contain significant amounts of liquidhydrocarbons because the presence of significant amounts of liquidhydrocarbons can make separation of CO₂ more difficult. Thus, liquidhydrocarbons present in the CO₂-containing hydrocarbon asset stream arepreferably separated prior to scrubbing. The separation of liquidhydrocarbons from the CO₂-containing hydrocarbon asset stream can alsobe conducted underwater.

During disposal of the CO₂-enriched sea water, or alternative aqueousliquid, stream by at least one of injection into a marine environment, aterrestrial formation, or combinations thereof, the pressure requiredfor injection may be greater than the pressure of the CO₂-containingstream exiting the scrubber. In such instances, pressure can beinexpensively increased using liquid phase pumps. In preferredembodiments, a pump used to inject a CO₂-enriched aqueous stream into aterrestrial formation is positioned at a depth greater than or equal toa depth of a separator separating the CO₂-enriched aqueous stream from ahydrocarbon asset. Ideally, the CO₂-containing stream is injected at apressure and temperature sufficient to ensure that the CO₂ does notvaporize, but remains dissolved in the aqueous liquid.

Various terrestrial formations are suitable for the disposal ofCO₂-enriched aqueous streams. For instance, suitable terrestrialformations include, but are not limited to, hydrocarbonaceousformations, non-hydrocarbonaceous formations, combinations thereof andthe like. Particularly suitable terrestrial formations include, but arenot limited to, underground natural liquid and gaseous formations, coalbeds, methane hydrates, combinations thereof and the like.

There are also numerous marine environments suitable for the disposal ofCO₂-enriched aqueous streams. For instance, suitable marine environmentsinclude, but are not limited to, oceans, seas, lakes, springs,reservoirs, pools, ponds, rivers, combinations thereof and the like.

A marine disposal site for a CO₂-enriched aqueous stream need not benear the scrubber, but can be some distance away from the scrubber. Forexample, if the hydrocarbon production facility is located in shallowwater, it may be desirable to dispose of the CO₂-enriched aqueous streamin a deep water disposal site some distance away from the productionfacility. Preferably, the marine disposal site is within about 10kilometers of the scrubber, more preferably it is within about 1kilometer of the scrubber and most preferably is within about 100 metersof the scrubber.

Although the CO₂-containing hydrocarbon asset source, depicted in FIG.1, is shown as being positioned underwater, the CO₂-containinghydrocarbon asset source does not have to be underwater. For instance,the hydrocarbon asset source can be positioned near a shore line withCO₂-containing hydrocarbon assets being pipelined to an offshorelocation where underwater scrubbing of CO₂ is performed. In addition,although it may be preferable to use sea water for scrubbing inprocesses of the present invention, there are several suitablealternative aqueous liquids that can be used instead of, or incombination with, sea water to scrub CO₂ from CO₂-containing hydrocarbonassets. Suitable alternative aqueous liquids include, but are notlimited to, reaction water formed in a Fischer-Tropsch Gas-To-Liquid(GTL) process, spent cooling water from a Fischer-Tropsch GTL facility,river water or other non potable water and water recovered from crude orgas production.

Ideally, the aqueous stream, preferably sea water, used to scrub CO₂from the CO₂-containing hydrocarbon asset has a pH that is as high aspossible. Preferably, the pH of the aqueous stream is greater than about7.0 in order to facilitate scrubbing of CO₂. Numerous suitabletechniques may be employed to increase the pH of the aqueous stream usedto scrub CO₂. One suitable way to increase the pH is to add an alkaliand/or other basic materials including, but not limited to, ammonia.Further, because the added basic materials are to be disposed of afterscrubbing, these materials should be inexpensive and benign to theenvironment in which they are intended to be disposed. Accordingly,given the economic and environmental constraints, preferred aqueoussources include, but are not limited to, sea water, river water andother non potable water sources.

Fischer-Tropsch GTL process water may be an especially suitable aqueousliquid for CO₂-scrubbing because GTL process water is abundantlyproduced during Fischer-Tropsch GTL processing. For example, thefollowing stoichiometric equation governing the overall conversion ofsynthesis gas to Fischer-Tropsch products: nCO+2nH₂→nH₂O+nCH₂, whereinnCH₂ represents a hydrocarbon product from a Fischer-Tropsch process,demonstrates that the weight ratio of water to hydrocarbon producedduring conversion is about 1.25. Thus, a typical Fischer-Tropsch processproduces about 25% more water than hydrocarbon, on a weight basis.Unfortunately, a problem with GTL process water is that it may containacidic contaminants such as, for example, acetic acid. Acidiccontaminants can lower the pH of the process water, thereby reducing CO₂solubility. Thus, if GTL process water is used to scrub CO₂ fromCO₂-containing hydrocarbon assets, it is preferable to remove acidiccontaminants from the GTL process water prior to using it as a scrubbingstream. Various suitable methods exist for removing acidic contaminantsfrom GTL process water including, but not limited to distillation,adsorption onto alumina or a basic material and oxidation.

If the scrubbing liquid used is not sea water, and contains air, thescrubbing liquid is preferably de-aerated prior to scrubbing.De-aeration of the scrubbing liquid increases a liquid's capacity toadsorb CO₂ and minimizes the introduction of air into the CO₂-containinghydrocarbon gas stream. Processes for de-aeration of aqueous streams arewell known and are used, for example, in desalination plants and forpreparation of boiler feed water. Such processes are described indetail, for example, in John H. Perry's Chemical Engineering Handbook,Fourth Edition, pages 9-51, McGraw Hill Book Company, 1963, the entiredisclosure of which is incorporated herein by reference.

In certain situations it may be preferable to dispose of theCO₂-enriched aqueous stream in the same formation used to supply theCO₂-enriched hydrocarbon asset. For instance, it may be preferable todispose of the CO ₂-enriched aqueous stream in the same formation fromwhich the hydrocarbon asset is supplied to maintain and/or augment thepressure of the formation. In addition, when pressure maintenance isdesirable, it may be beneficial to, at least partially, vaporize the CO₂during injection rather than before or during pumping. CO₂ vaporizationcan be achieved by reducing the pH of the aqueous stream. A suitable wayto reduce the pH of the aqueous stream is to inject an acid. Inprocesses of the present invention, acid may be conveniently obtainedfrom acidic waste water produced by a GTL facility. Thus, in a preferredembodiment, a CO₂-enriched aqueous stream is injected into a formationnot only to dispose of the CO₂ removed from the hydrocarbon assetstream, but also to maintain the pressure in the formation. Furthermore,an acidic stream can be injected into the formation to induce CO₂vaporization by reducing the pH of the aqueous stream. Mixing of theacidic stream and the CO₂-enriched aqueous stream can be conducted atvarious suitable locations. However, to minimize problems that may beassociated with compression, it is preferable to mix the acidic solutionand the CO₂-enriched aqueous stream after they have been separatelycompressed. Mixing can take place in the formation, for example, byusing either separate wells or by alternating injection of the streams.Mixing can also be conducted above ground after the liquids have beenpressurized.

In addition to maintaining and/or augmenting formation pressure, theinjection of an aqueous stream, possibly with an added surfactant, intoa terrestrial formation can facilitate hydrocarbon asset recovery and/orproduction.

If the CO₂-enriched hydrocarbon asset stream contains relatively lowamounts of CO₂, in comparison with other gases, the aqueous stream maynot be highly selective to scrubbing CO₂. In such instances, it may bepreferable to conduct scrubbing in stages. For example, a firstselective CO₂ scrubbing operation may be conducted followed by adesorption operation to generate a concentrated CO₂ gas stream, followedby scrubbing with an aqueous stream. Technology for selective scrubbingof CO₂ is well known in the art and typically uses amines.

While operating conditions may vary, in preferred embodiments operatingconditions are adjusted to ensure that the hydrocarbon asset is in a gasphase during contact with the aqueous liquid stream. That is, inpreferred embodiments, temperature, pressure, pH and contacting durationshould be sufficient to ensure that at least about 75%, more preferablyat least about 85% and most preferably at least about 90% by weight ofthe hydrocarbon asset is in a gas phase. In addition, it preferable toadjust and/or set operating conditions during contacting of thehydrocarbon asset and the aqueous liquid stream and/or during separationof the CO₂-enriched aqueous stream after contacting, so that thesolubility of CO₂ relative to methane in the aqueous liquid stream isenhanced. Similarly, it is preferable to set and/or adjust operatingconditions such as, for example, pressure, temperature, pH andcontacting duration, during contacting and/or separation to minimizemethane hydrate formation.

Finally, in preferred embodiments, disposal of a CO₂-enriched aqueousstream should be conducted at a depth, pressure, temperature and pHsufficient to ensure that at least about 75%, more preferably at leastabout 85% and most preferably at least about 90% of the CO₂ removed froma hydrocarbon asset remains dissolved in the aqueous stream.

Although there are numerous suitable scrubbers that can be used in theconjunction with the present invention, scrubbers that are capable ofoperating underwater are preferred. In particular, scrubbers thatminimize the use of complex equipment, such as pumps and control valves,may be especially preferred.

An additional preferred embodiment of the present invention is depictedin FIG. 2. In this embodiment, a CO₂-containing hydrocarbon asset stream22 is provided from a CO₂-containing hydrocarbon asset source 21. TheCO₂-containing hydrocarbon asset stream 22 passes through a pressurereducer 23, that, if necessary, reduces the pressure of the hydrocarbonasset stream 22. The hydrocarbon asset stream 22 then enters a scrubber24. In this embodiment the scrubber 24 is a long tube filled with slowlydownward moving sea water that enters the scrubber 24 in a sea waterstream 26. The hydrocarbon asset stream 22, preferably in the form of agas, is injected into a bottom section of the tube above a dischargepoint for a CO₂-containing sea water exit stream 30. The hydrocarbonasset stream 22, in the form of a gas 25, rises in the tube through seawater and is scrubbed. The pressure of the hydrocarbon asset gas 25 atthe top of the tube is maintained at above about atomospheric pressurein order to keep the level of sea water in the tube slightly below thesurrounding sea level. The sea water stream 26 is pumped into the tubeat a rate sufficient to remove a desired amount of CO₂. The pumping rateis adjusted to reach a desired level of CO₂ removal. The diameter of thetube is selected so that at a desired sea water pumping rate andhydrocarbon production rate, a downward flow of sea water will notexceed an upward gas bubble velocity. After scrubbing, a CO₂-depletedhydrocarbon stream 27 exits the process above the sea level 28.Similarly, after scrubbing, a CO₂-containing sea water stream 30 exitsthe scrubber 24 for at least one of marine disposal and disposal in anunderground reservoir 32. If disposed of in an underground reservoir 32,the CO₂-containing sea water is directed under the sea bed 29 to theunderground CO₂ disposal reservoir 32.

EXAMPLES Example 1

A CO₂-rich source of natural gas from an undersea source is obtainedwith the following molar composition: about 80% CH₄, about 20% CO₂ and atrace amount of H₂S. The gas is scrubbed in a counter-current contactorwith de-aerated sea water at about 0° C. or about 30° C. and about 300psig to remove approximately 90% of the CO₂ and to produce a gas withonly about 2% CO₂. A pressure of about 300 psig is equivalent to a waterdepth of about 700 feet. The minimum amount of water need per mole ofgas along with gas composition and selectivity is as follows:

Temperature 0° C. 30° C. Water required, gal/SCF gas 0.16 0.4(equilibrium limit) Water required, gal/SCF gas 0.19 0.5 (practical)Scrubbing Gas Composition Carbon Dioxide 2 2 Methane 98 98 HydrogenSulfide low low Percent Removal Carbon Dioxide 90 90 Methane loss 3.2%4.4% Hydrogen Sulfide high high

The above table provides data for both equilibrium and practical waterrequirements. The equilibrium value is calculated with equilibriumconstants. In practice, some water such as, for example, about 20%, isrequired to overcome slow transfer that can occur as adsorptionapproaches equilibrium, and to compensate for slight effects caused bydissolved air if non-de-aerated water is used as the scrubbing fluid.

From the above data, it can be seen that scrubbing can effectivelyremove CO₂ with an acceptable loss of methane. In addition toeffectively removing CO₂, the above process provides the added benefitof removing hydrogen sulfide. Scrubbing at a relatively low temperatureis preferred in order to minimize hydrocarbon loss and water-flowrequirements.

While the present invention has been described with reference tospecific embodiments, this application is intended to cover thosevarious changes and substitutions that may be made by those of ordinaryskill in the art without departing from the spirit and scope of theappended claims.

What is claimed is:
 1. A method for removing CO₂ from a CO₂-containinghydrocarbon asset, the method comprising: a) contacting a CO₂-containinghydrocarbon asset with an aqueous liquid stream at an underwaterlocation so that at least a portion of the CO₂ in the hydrocarbon assetis dissolved into the aqueous liquid stream, creating a CO₂-depletedhydrocarbon asset and a CO₂-enriched aqueous stream, wherein duringcontact with the aqueous liquid stream, temperature, pressure, pH, andcontacting duration are sufficient to ensure that at least about 90% byweight of the hydrocarbon asset is in a gas phase; b) separating theCO₂-enriched aqueous stream from the hydrocarbon asset; and c) disposingof the CO₂-enriched aqueous stream in at least one of a marineenvironment, a terrestrial formation or combination thereof.
 2. Themethod of claim 1, further comprising contacting the hydrocarbon assetwith the aqueous liquid stream at an underwater location that is at adepth where hydrostatic water pressure is equal to or less than apressure of a source supplying the hydrocarbon asset.
 3. The method ofclaim 1, further comprising separating the CO₂-enriched aqueous streamfrom the hydrocarbon asset at an underwater location at a pressuregreater than about atmospheric pressure.
 4. The method of claim 1,wherein disposal of the CO₂-enriched aqueous phase is conducted at adepth, temperature and pH sufficient to ensure that at least about 90%of the CO₂ removed from the hydrocarbon asset remains dissolved in theaqueous phase.
 5. The method of claim 1, wherein the aqueous liquid isselected from the group consisting essentially of reaction water formedin a Fischer-Tropsch GTL process, spent cooling water from aFischer-Tropsch GTL facility, river water, other non-potable watersources, water recovered from crude or gas production, sea water andcombinations thereof.
 6. The method of claim 1, wherein the aqueousstream is comprised of sea water.
 7. The method of claim 1, wherein theterrestrial formation is selected from the group consisting essentiallyof hydrocarbonaceous formations, non-hydrocarbonaceous formations andcombinations thereof.
 8. The method of claim 1, wherein contacting isperformed in a device that employs movement of the aqueous liquid awayfrom a surface of a body of water and movement of the CO₂-containinghydrocarbon asset towards the surface of the body of water.
 9. A processfor producing a CO₂-depleted hydrocarbon gas from a hydrocarbon/CO₂ gasmixture, the method comprising: a) contacting a hydrocarbon/CO₂ gasmixture underwater with an aqueous liquid stream so that at least aportion of the CO₂ in the gas mixture is dissolved in the aqueous liquidstream, creating a CO₂-depleted hydrocarbon gas and a CO₂-enrichedaqueous stream, wherein during contact with the aqueous liquid stream,temperature, pressure, pH, and contacting duration are sufficient toensure that at least about 90% by weight of the hydrocarbon/CO₂ gasmixture is in a gas phase; b) separating the CO₂-enriched aqueous streamfrom the hydrocarbon gas; and c) producing a CO₂-depleted hydrocarbongas.
 10. The process of claim 9, further comprising processing theCO₂-depleted hydrocarbon gas after separation of the CO₂-enrichedaqueous stream using a processing step selected from the groupconsisting of compression, condensation, separation of liquids, sulfurremoval, dehydration, mercury removal, radon removal, blending withother gas streams, heating, valve adjustment and combinations thereof.11. The process of claim 9, further comprising disposing of theCO₂-enriched aqueous stream at a depth, pressure, temperature and pHsufficient to ensure that at least about 90% of the CO₂ removed from thegas mixture remains dissolved in the aqueous liquid stream.
 12. Theprocess of claim 9, further comprising disposing of the CO₂-enrichedaqueous stream in at least one of a marine environment, a terrestrialformation and combinations thereof.
 13. The process of claim 12, whereinthe terrestrial formation is selected from the group consistingessentially of hydrocarbonaceous formations, non-hydrocarbonaceousformations and combinations thereof.
 14. The process of claim 9, whereinthe aqueous liquid stream is at least one liquid selected from the groupconsisting essentially of reaction water formed in a Fischer-Tropsch GTLprocess, spent cooling water from a Fischer-Tropsch GTL facility, riverwater, other non-potable water sources, water recovered from crude orgas production, sea water and combinations thereof.
 15. The process ofclaim 9, wherein contact between the gas mixture and the aqueous liquidstream is made at an underwater location at a depth where hydrostaticwater pressure is equal to or less than a pressure of a source supplyingthe gas mixture.
 16. The process of claim 9, further comprisingseparating the CO₂-enriched aqueous stream from the hydrocarbon gas at apressure greater than about atmospheric pressure.
 17. The process ofclaim 9, wherein contacting of the gas mixture and the aqueous liquidstream is conducted using a device wherein the aqueous liquid streammoves in a direction away from a surface of a body of water and whereinthe gas mixture moves in a direction towards the surface of the body ofwater.
 18. A method for removing CO₂ from a CO₂-containing hydrocarbonasset, the method comprising: a) at an underwater location, contacting aCO₂-containing hydrocarbon asset with an aqueous liquid stream,comprised of sea water and at a pressure greater than about atmosphericpressure, so that at least a portion of the CO₂ in the hydrocarbon assetis dissolved into the aqueous liquid stream, creating a CO₂-depletedhydrocarbon asset and a CO₂-enriched aqueous stream, wherein duringcontact with the aqueous liquid stream, temperature, pressure, pH, andcontacting duration are sufficient to ensure that at least about 90% byweight of the hydrocarbon asset is in a gas phase; b) separating theCO₂-enriched aqueous stream from the hydrocarbon asset; and c) disposingof the CO₂-enriched aqueous stream in at least one of a marineenvironment, a terrestrial formation or combination thereof.
 19. Aprocess for producing a CO₂-depleted hydrocarbon gas from ahydrocarbon/CO₂ gas mixture, the method comprising: a) contacting ahydrocarbon/CO₂ gas mixture underwater with an aqueous liquid stream,comprising sea water and at a pressure greater than about atmosphericpressure so that at least a portion of the CO₂ in the gas mixture isdissolved in the aqueous liquid stream, creating a CO₂-depletedhydrocarbon gas and a CO₂-enriched aqueous stream, wherein duringcontact with the aqueous liquid stream, temperature, pressure, pH, andcontacting duration are sufficient to ensure that at least about 90% byweight of the hydrocarbon/CO₂ gas mixture is in a gas phase; b)separating the CO₂-enriched aqueous stream from the hydrocarbon gas; andc) producing a CO₂-depleted hydrocarbon gas.